Seismic prospecting techniques are commonly used in the search for subsurface hydrocarbon deposits. In seismic prospecting, an energy source generates signals which propagate into the earth and reflect from subsurface formations. The reflections are recorded by a multitude of receivers on or near the surface of the earth, or in an overlying body of water. This process is repeated for a number of source and receiver locations, and the recorded reflections are processed to develop images of the subsurface. Skilled analysts can use those images to predict whether oil or gas is present in the formations.
The cost and complexity of seismic data acquisition and processing, as well as the accuracy of the images that are obtained, are largely functions of the locations at which the sources and receivers are placed. For example, where the sources and receivers are on the surface, acquisition costs are generally low and the data can be analyzed in a straightforward manner using generally well understood types of data processing. Typically, the data from combinations of source and receiver positions are stacked together to generate an estimated image of the subsurface formations. Next, inaccuracies in the image, which result from subsurface structural complexities and seismic velocity variations, are eliminated to the extent possible by reflector migration. Those skilled in the art of seismic data processing will understand that migration may be performed either before or after stacking. The fact that both the sources and the receivers are on the surface and therefore have the same reference position, referred to as the datum, facilitates data processing.
Despite that low cost and relative simplicity, surface seismic data does pose challenges to the analyst. A subsurface seismic velocity model must be generated to stack the data and to perform the migration. The accuracy of the images produced depends to a great extent on the accuracy of this velocity model. Unfortunately, the model is often only an estimate of the actual subsurface velocity structure, not necessarily based on sufficient data, and inaccuracies in stacking and migration may result. In addition, images from surface seismic data are degraded in quality due to the influence of the weathered near-surface layer, which may also have irregular topography, on the seismic reflections.
The problems associated with surface seismic data are particularly acute where, for example, the analyst must accurately migrate steeply dipping or overturned reflectors such as salt flanks, image below complex velocity structures such as salt sills, or image in areas where a complex near-surface layer causes severe ray-path complications or static time shift problems. One method of overcoming these problems is to obtain data from sources and/or receivers placed below the surface in boreholes. Borehole seismic data are less sensitive to velocity errors because the raypaths used to form the images are much shorter than those used for surface seismic imaging. Borehole seismic data may also eliminate salt flank, salt sill, and weathered near-surface layer velocity complications by completely bypassing those features.
Two broad categories of borehole data acquisition techniques are commonly used: vertical seismic profiling and crosshole surveying. Vertical seismic profiling (VSP) may involve either forward or reverse geometry data gathering. Forward profiling involves placing seismic sources on the surface and receivers in a bore-hole. Reverse profiling places the sources in the borehole and the receivers on the surface. In either case, VSP surveys have several advantages over surface seismic data acquisition. These advantages include an improved ability to construct lateral images, reduced errors due to ray-bending and attenuation effects, and improved horizontal and vertical data resolution.
Crosshole surveying involves placing seismic sources in a first borehole and receivers in a second borehole. A number of advantages result from this source-receiver geometry, as compared to surface seismic and VSP data. Direct arrival travel times, required to form images of the velocity structure between wells, are relatively easy to determine from crosshole data. Crosshole data also have the advantage of being insensitive to near-surface velocity variations because the sources and receivers can be positioned below complex velocity structures. This advantage eliminates the problems associated with reflector imaging through such structures. Finally, cross-hole data have much broader bandwidths than do surface seismic or VSP data, leading to better quality images when data processing has been completed.
Despite their advantages, VSP and crosshole data suffer from several problems that limit their usefulness. In both types of data, the receivers have a different datum than do the sources. For example, forward VSP data involves sources with a surface datum and receivers with a borehole datum. This dual datum data increases the complexity and cost of data processing as compared to data which is referenced to a single datum. In addition, both VSP and crosshole data are expensive to gather. Part of that expense results from data acquisition costs, which includes the cost of drilling a borehole, if one is not otherwise available. Finally, both data types have processing limitations. For example, accurate images of steeply dipping structures are difficult to generate using either technique.
Crosshole and reverse profiling VSP data are particularly expensive to acquire because downhole seismic sources must be used. Because these sources have to be weak enough not to cause damage to the borehole, the strength and range of penetration of the signal is limited. Although the signal-to-noise ratio can be improved by repeated firing of the source, that process is expensive and time-consuming. As a result, crosshole data cannot generally be gathered between wells that are more than a few thousand feet apart.
Because of the individual advantages of surface seismic and borehole data, the oil and gas industry has focused in recent years on developing combined techniques which preserve the benefits of each while eliminating the disadvantages. For example, U.S. Pat. No. 4,926,393 to McClellan, Adams, and Cox ("McClellan") discloses a method of data acquisition and analysis intended to improve the accuracy of steep dip imaging by allowing application of surface data processing techniques to VSP data. McClellan first obtains VSP data from a multitude of surface source positions covering a range of distances from a borehole in which the VSP receivers have been placed. The source positions are on the opposite side of the borehole from a geophysical feature of interest. The borehole receivers record both direct arrival and reflection signals. The time shift between each reflection signal and the corresponding direct arrival is used to extrapolate the surface sources to the borehole. Because both the sources and the receivers have the same borehole datum after the extrapolation, the dataset is more amenable to conventional processing.
Despite the simplifications associated with the ability to use conventional processing, McClellan suffers from several limitations. First, the VSP data that is required is expensive because the signal-to-noise ratio must be sufficient to determine both direct arrival times and reflection times. In addition, depending on the location of the borehole, shallow dips can only be imaged within a limited region of the subsurface. Finally, because McClellan relies on travel time calculations only, the extrapolation of the data from the surface to the borehole is inaccurate due to the loss of amplitude and phase information.
The publication of R. Ala'i, "From Surface to VSP Data" Delft Vol. IV: From Seismic Measurements to Rock and Pore Parameters, 1993, proposes a method superficially similar to McClellan, but employing surface data only. Ala'i simulates VSP data by extrapolating surface seismic receivers to the location of a well. Images are then obtained from the extrapolated data using conventional VSP imaging techniques. However, the extrapolation must be performed using an assumed velocity model rather than from measured travel times. As a result, the accuracy of the simulated VSP data is limited by the accuracy of that model. Due to that limitation, the method does not reliably improve imaging accuracy as compared to conventional surface imaging techniques.
Other commonly employed methods of imaging reflectors using VSP data include the VSP-CDP transform and direct prestack migration. The VSP-CDP transform, as in U.S. Pat. No. 4,627,036 to K. D. Wyatt for example, determines, for each sample in each input trace, the subsurface location that would produce a reflection at that time sample. This determination is based on a model for the velocity of propagation of seismic waves in the region to be imaged. Assumptions may also be made about the dip of the reflectors. Direct prestack migration methods, as in the publication by J. W. Wiggins "Kirchoff Integral Extrapolation and Migration of Nonplanar Data," Geophysics, Vol. 49, No. 8, 1984, use the wave equation to extrapolate borehole seismic data to the location where an image is desired.
Both the VSP-CDP transform and direct prestack-migration suffer from the velocity model limitations discussed above. Specifically, an input required by both techniques is the seismic interval velocity field for the region to be imaged. Without an accurate estimate of that field, the techniques will not image reflectors into the correct position. In addition, images from different source locations will not add coherently, resulting in low signal-to-noise ratio images. The method of Blakeslee and Chen in copending application 08/019501 addresses this velocity field limitation for the limited application of crosshole traveltime tomography. The method, which requires two boreholes, allows a crosshole seismic velocity field to be determined from surface seismic sources and downhole receivers. However, the method is not applicable to single borehole data acquisition configurations, and cannot be used for reflector imaging or diffraction tomography.
From the foregoing it can be seen that an improved method of imaging complex seismic features is required. Preferably, the method should allow the use of a source-receiver configuration during data acquisition which is cost-effective and straightforward to implement. The method should also involve transformation of the data into a source-receiver configuration from which accurate images of subsurface structural features can be obtained using convenient, cost-effective data processing and interpretation techniques. The transformation from the data acquisition configuration to the imaging configuration should retain the data's important amplitude and phase information, and not require knowledge of the seismic velocity field in the extrapolation region. The present invention satisfies these needs.